Environment-friendly marine fuel

ABSTRACT

For the shipping industry, these fuels provide solutions to long outstanding technical problems that heretofore hindered supply of low sulfur marine fuels in quantities needed to meet worldwide sulfur reduction goals. Marine shipping use of high sulfur bunker oils is reported as largest source of world-wide transportation SOx emissions. When ships on the open seas burn cheap low grade heavy bunker oils high in sulfur, nitrogen and metals, the SOx, NOx, and metal oxides go to the environment. This invention converts essentially all of each barrel of crude feed to a single ultraclean fuel versus conventional refining where crude feed is cut into many pieces, and each piece is sent down a separate market path meeting various different product specifications. When in port, ships can use these fuels to generate and sell electricity to land based electrical grids to offset fuel cost in an environment-friendly manner.

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a divisional of U.S. Ser. No. 16/731,657 filed onDec. 31, 2019, which is a divisional of U.S. Ser. No. 16/089,894 filedon Sep. 28, 2018, which is a 371 National Phase of InternationalApplication Serial No. PCT/US2016/057540 filed on 18 Oct. 2016, all ofwhich are incorporated herein by reference.

FIELD OF THE INVENTION

The invention relates to methods and apparatus to produce very lowsulfur fuels from crude oils, refinery residual oils and othercontaminated liquid feeds. Very low sulfur fuels made by this inventionare especially cost effective for on-board large marine transportvessels and for on-shore large land based combustion gas turbines.

BACKGROUND OF THE INVENTION

This invention targets a long well known, large environmental problem,previously unsolved, that when ships ‘on the open seas’ burn cheap lowgrade heavy bunker oils and other heavy residues high in sulfur,nitrogen and metals, the oxides of sulfur, nitrogen and metals go to theenvironment. Such emissions are worldwide, not recognizing domesticgeographical boundaries. Various third party reports indicate thatcertain global emissions generated by marine burning of such heavy fuelsfor water transport are many multiples higher than combined worldwide onshort vehicle fleets burning gasoline and diesel fleets. Such marineburning produces emissions of SOx, NOx, CO2, soot and noxious metals. Onshore vehicle fleets include cars, trucks, and others, many of which arenow using mandated “highway fuels” having very low sulfur content. Thus,even if transport by such large ships is efficient based on ‘ton offreight per mile’ and fuel consumed basis, the reality is such shipsgenerate large emissions.

Implementation of certain key regulations mandating ships' use ofclearer burning marine fuels is conditional upon sufficient quantitiesof such fuels being available. Rightly so to not command that which isnot possible or practical, either technically or economically, yet asolution is needed.

For example, the International Maritime Organization (IMO), a divisionof the United Nations, issues regulations pertaining to internationalshipping. IMO has sought to reduce emissions by issuing more stringentsulfur limits for maritime fuels, while recognizing technicalconstraints. IMO has required fuels that marine fuels fired after 2011at open sea must have a sulfur content not exceeding 3.50% m/m (e.g.fired outside defined Emission Control Areas (ECAs) including 200nautical miles from shores of United States, Europe and certain otherareas). At 2015, IMO revised its regulations to limit marine fuel sulfurcontent to generally less then 0.1% sulfur for commercial ships withindesignated ECAs.

Yet for 2020 and later, IMO has again dropped open sea sulfur limitssignificantly to 0.50% m/m. However, IMO notes such aggressive drop in2020 depends “on the outcome of a review, to be concluded by 2018, as tothe availability of the required fuel oil” and suggests possibledeferral of such drop to 2025 if required fuels are not available. Seethe Convention on Marine Pollution (MARPOL), Annex VI, for regulationsof Air Pollution in the Maritime Industry. Thus there is real,significant likelihood of a problem with lack of supply availability oflow sulfur marine fuels and lack of technology to achieve such supply.For illustration, an industry publication in 2015 stated that “plans arein place to reduce the sulfur content allowed in fuels to below the[2014] levels required in Emission Control Areas . . . but this is yearsaway because current technology would make that cost prohibitive formany shipping companies. Such publication further states that “due tothe extra costs and possible mechanical issues, these regulations arecontinuously reevaluated and phased approaches are used forimplementation” since many marine engines are not designed to handle lowsulfur gas oil because it is so much thinner than heavy fuel oil and itdoes not have the lubrication properties of the heavy fuel oil.Companies are using various workarounds to make it work, such aschilling the fuel to increase the viscosity or injecting extra lubricantinto certain parts of the engine.” Internet article published by Quoraentitled “Is it true that the 15 biggest ships in the world produce morepollution than all the cars? by Josiah Toepfer, CG Office, ShipInspector/Auditor, Casualty Investigator.

Another illustration is that, at 2015, IMO regulations dropped marinefuel sulfur content to a maximum of 0.1% sulfur for commercial shipswithin designated ECAs. Before entering ECAs, vessels must change fuelsfrom sulfur rich, but low cost high sulfur heavy bunker fuel oil firedat open sea, to an expensive low sulfur fuel akin to highway dieselfuel. Drop of inside ECAs fuel sulfur from 1.00% m/m (for after 1 Jul.2010) to 0.10% m/m for after 1 Jan. 2015 has created market supply andpricing challenges. Production and supply of such fuels for marine usefor IMO related regulatory compliance competes with distillate fuelneeds for highway and other onshore diesel applications and shiftsavailable preferred feed streams, and also existing refinery apparatusand feed supply networks, away from highway use of diesel and other lowsulfur distillates. Also, other technical issues arise onboard.

Regarding the 2015 IMO drop of sulfur content within ECAs, the UnitedStates Coast Guard issued alerts that “vessels using higher sulfurcontent fuels must change to ultra low sulfur (ULS) fuel oil to comply”with new regulations. Vessels must use ULS fuel oil on inbound andoutbound transits, at the dock, and anytime within an ECA, thus eachship which uses higher sulfur content fuel oil is required to developand implement changeover procedures for switching between residual anddistillate fuels before entering ECAs. The Coast Guard further cautionedthat “there are many other important technical issues associated withthe use of ultra low sulfur fuel oils and fuel oil switching addressedin documents produced by class societies, insurers, engine manufacturersand industry associations” and that “the energy content of a givenvolume of ULS fuel oil may differ from residual fuel, such that existingthrottle settings may not give the desired propeller shaft RPM orgenerator loads”. United States Coast Guard U.S. Department of HomelandSecurity Inspections and Compliance Directorate Mar. 3, 2015 SafetyAlert 2-15 Washington, D.C. Ultra Low Sulfur Fuel Oil & Compliance withMARPOL Requirements Before entering and while operating within EmissionControl Areas.

A stark reality is that refineries are expensive, requiring significantcapital investments even for what seem like relatively minor changes tofuel product or production apparatus or addition of unit operations. Inthe 2003 era, European refinery assessment studies were conducted inanticipation of needs for lower levels of contaminants in marine fuelsand requirements and capabilities for producing same in necessaryquantities. See for example Advice on Marine Fuel, Potential pricepremium for 0.5% S marine fuel; Particular issues facing fuel producersin different parts of the EU; and Commentary on marine fuels market,Draft Final Report Contract Number ENV.C1/SER/2001/0063. Order Slip n°C.1/3/2003. European Commission—Directorate General Environment, October2003.

Such reports suggested great challenges, such as higher costs ordecreases in refinery utilization or efficiency, when seeking to producenecessary quantities of suitable marine fuels in many countries,including in some instances, absence of local basic facilities nearmajor ports to locally make and supply such marine fuels as well as theabsence of technology and apparatus to so make such fuels.

The cited reports saw only three options. A “re-blending option”(blending heavy fuel oils with low sulfur fuels) was viewed as thelowest cost option for producing low sulfur bunkers, yet such was notadequate as it would only treat the lowest quantity of material no majorcosts. The option had relatively small costs associated to logistics forthe re-blending of different categories of heavy fuels then currentlyproduced by the European refineries but failed on quantities.

The second alternative by increased cost is the processing lower sulfurcrude oils, by replacing high sulfur content crudes, such as ArabianLight, which was reported to contain 1.8% sulfur, with lower sulfurcrudes, for instance by African crudes such as Bonny Light which wasreported to contain 0.14% sulfur by weight. The estimated incrementalcosts for marine bunkers incurred by this alternative were consideredexcessive burdens for reasons set forth in the reports.

Finally, the old era reports mention a third most expensive option forthe production of low sulfur marine grade fuels by desulfurization ofvacuum residue (VRDS). The report concludes that “it is important tonotice, however, that as opposed to the degree of desulfurizationrequired for petrol or diesel, hydrotreating of the bottom of the barrel(residue desulfurization) is not a process that refiners are currentlyconsidering to implement per se, that is if it is not coupled with someconversion of residue to lighter products. Nonetheless, if VRDS waspursued for the sole objective of desulfurization of vacuum residue, thecosts of this alternative” were be about double the second alternative,and therefore even more unacceptable.

To meet IMO requirements with prior art technologies, a ship operatorcan bunker both high sulfur content fuel oil for use at sea and a lowsulfur content for use within an ECA; however, this choice can faceissues with technology of the engines, lubricity, and possible needs fordifferent fuel injection systems for optimum operations and mechanics ofswitching fuels. An operator can add post combustion flue treatmentapparatus which may be relatively large, expensive and complex tomaintain at highest performance levels. In some instances, liquefiednatural gas (LNG) can be considered for used as marine fuel where, forexample, some transportation carriers of LNG may elect to use ‘boil offgas’ for fuel, yet to extend this LNG engine concept to all cargo shipswould require wide spread LNG refueling stations infrastructure which isvery costly, with added costs for those ports in locations which do nothave local natural gas production supplies or liquefaction facilities.However, in all cases, LNG use in lieu of liquids carries with such usea real risk of methane release during either bunking by venting whilerefueling or incomplete combustion or otherwise during operations andmaintenance. Such methane release is of concern since methane isattributed by some with many multiple times the impact as a greenhousegas on the environment than sulfur dioxide. In a similar vein, someassert that emission reductions can be attained in marine applicationsby firing natural gas during shipping transport or while in port asfacilitated by a harbor with a gas feed docking station. However, fromone technical overview perspective, natural gas retains the methane leakissue and firing natural gas reduces CO2 emissions not because itreleases less CO2, but instead, when compared to LNG, natural gas useavoids the CO2 emissions generated during processing to liquefy LNG andreduces CO2 when backing off or replacing coal for firing power plantsthat supply ships while in port. Development activities that push forLNG or natural gas to replace liquids as marine fuels as useful toconsider but such do not provide any practical cost effective marinesolution when there is a lack of worldwide gas infrastructure and newfueling infrastructure is needed, which gas distribution infrastructureis equipment and capital intense at ports in countries where localsupplies of gas are not produced.

There is a need to solve these global environmental issues with marinefuels that are recognized, have going on for many years without a costeffective technical solution. In addition, availability of novel lowcosts fuels made by novel process configurations and apparatus shouldencourage ship owners to install highly efficient combined cyclepropulsion power generation systems that have higher efficiency overdiesel engines due to efficient use of waste heat recovery and do nothave an issue with lack of fuel lubricity as do many engines when firingmore expensive ultralow sulfur diesel that in limited supply.

However, there has long been a gap in effective fuels productiontechnology causing a supply shortage of large quantities of very lowsulfur marine fuels at low cost. The need to fill the gap remains.

International Energy Agency (EIA), Oil Industry and Markets Divisionpublishes official public notes which describe processes and apparatusconfigurations used to produce fuel and describe conventional refineryconfigurations, products and margins. Terms used in herein, unlessseparately defined or expressly modified, shall have meaning assigned bythe “Glossary, Source: U.S. Energy Information Administration (October2016)” which is incorporated herein for all purposes. EIA publicationsdefine and discuss configurations for processing crude oils, allsplitting each barrel of crude feed into multiple products for differentapplications or downstream processing.

The genetics of development or growth conventional refineries issomewhat root stock based on society's evolution of demands forproducts, evolving away from basic kerosene grade distillates forlighting toward multiple products such gasoline and diesel for vehicles,then aviation grade fuels, then feedstocks for many downstream chemicalsapplications. Refinery technical developments appear typically to haveevolved in increments, directed as adaptations to either to maximize anamount of a given split from each barrel of crude for a particularmarket segment or to adapt refinery various streams for downstreamchemicals production, all while retaining production of multipleproducts for different end use applications.

Thus, prior art refinery designs which use atmospheric crude and/orvacuum distillation units, solvent separations, hydrotreating,gasification, and many other unit operations, split each barrel of crudefeed into multiple products each with different specifications fordifferent applications or downstream processing.

In conventional refining is counter-intuitive to separate the feed intodifferent unit effluent and then recombine all of such effluents. Forillustration, EIA above reference defines and describes conventional ortypical atmospheric crude oil distillation, vacuum distillation, fuelsolvent deasphalting, catalytic hydrotreating, and integratedgasification-combined cycle technology, but not a configuration of suchprocesses to convert substantially all of the crude oil feed to make asole liquid fuel.

Within the scope of conventional refining processes are ‘upgrading’,‘topping’ or ‘hydroskimming’ facilities. With crude upgraders, a primaryobjective is converting normally very heavy, highly viscous orsolids-entrained materials so they can be re-processed in existingconventional refineries that process lighter, flowable materials to makea full range of fuel products, chemical feedstocks and/or petroleumcoke. The upgraders are merely converting heavier to lighter densitycrude for feed conventional refineries that are individually designed toaddress sulfur to meet each of their respective downstream productspecifications and reduction of sulfur or elimination of metals is not aprimary objective of upgraders. The goal is upgrading source materialshaving extremely high densities compared to typical lower density crudesources. Heavier materials are rejected or separated out of sourcedsubstances so resulting densities of upgraded product materials approachdensities of crudes processed by existing conventional refineryequipment configurations. With regard to topping or ‘mini’ refineries,such are often located in remote or crude source opportunisticlocations. Topping refineries typically split each barrel of crude feedinto multiple straight run fractions targeted for naphtha, not gasolineproduction, with no or minimal subsequent processing except, in somelimited cases, naphtha reforming for gasoline octane enhancement andhydrotreating multiple distillates to produce a variety of products. Atypical topping refinery objective is to make a wide range of directlyusable fuel usable products, such as gasoline, kerosene, diesel and fueloil for local markets' consumption. In some undesirable practices oftopping and use of their products or their failure to properly addressresiduals, harmful emissions to the environment are increased, notdecreased. With hydroskimming refineries, crude is converted to multipleproducts akin to topping refineries, but typically with the limitedaddition of heavy naphtha reformers that also generate hydrogen which isconsumed by hydrotreaters in producing diesels. Hydroskimmers, liketopping refineries, typically make a wide range of gasoline, kerosene,diesel and fuel oil for local consumption, not just one product.

Various aspects of adapting hydrotreating, including having separateseries or parallel hydrotreating reactor zones or having integratedhydrotreating reactor zones, are known in art. PCT/US1999/00478(1998)published by Cash et al, and the references cited therein, discloseintegrated hydrotreating of dissimilar feeds, where hydrogen-containingand liquids-containing streams from separate hydrotreating zones areshared or combined in the manner disclosed therein. Various aspects ofuse of solvent separation, to extract deasphalted oil from pitch withinheavy residual streams, and use the deasphalted oil as feed tohydrotreating are known in art when used to produce multiple productstreams. For example, U.S. Pat. No. 7,686,941 (2010) to Brierley et aldiscusses solvent deasphalting for production of deasphalted oil,without cracking or degradation by separation of the feed based onsolubility in a liquid solvent, such as propane or other paraffinicsolvent such butane, pentane and others up to and including to heptane.The pitch remaining contains a high metals and sulfur content. Thedeasphalted oil can be hydrotreated for sulfur, nitrogen, concarbon andmetals removal as discussed in such reference for production of severalproducts including naphtha, kerosene, diesel and a residual material.

The global market needs to have available bulk quantities of fuels lowin sulfur and nitrogen and essentially free of metal contaminants toaddress global environmental issues on the open seas or at on-shorelocations having little or no natural gas resources where high sulfurfuel oil or raw crude is used at low efficiency for power generation.

Fuel producers need designs, which are different than those that haveevolved for conventional refining to produce multiple product slates. Tokeep costs low, the designs should be equipped, in a low capitalinvestment manner, only with apparatus essential make bulk quantities ofclean fuels in a cost effective and thermally efficient manner. Thedesigns should be targeted to make primarily marine fuel, not merelyextract a relatively small fraction of each barrel of crude for marinefuels and not use the larger portion of the barrel for otherapplications.

What the world needs is a “game changer” novel process that provides asolution to technical problems on how to make large quantities ofrelatively clean liquid fuels (in an efficient form for use to avoidwaste of energy expressed in short form as British Thermal Units (BTUs)in an economical manner for marine applications. Such process shouldhave minimal required infrastructure and associated capital andoperating costs since existing liquids-based marine fueling stations(for illustration those supplying high sulfur fuel oil (HSFO)) spreadall over the world can be used for distribution of such fuels in lieu ofhaving to create new infrastructures for LNG. Any such new processshould directionally support making liquid BTUs available costeffectively compared to ultralow sulfur diesel (ULSD) produced primarilyfor automotive and truck use, which diesel available is widelyavailable, but not used widely at sea by large marine transport carriersdue to cost and lubricity issues when ULSD is used in many existingmarine diesel engines.

BRIEF SUMMARY OF THE INVENTION

This invention fills a gap in effective fuels production technologyenabling low cost supply of large quantities of fuels having very lowsulfur, nitrogen, and essentially metals free, particularly usefuloffshore in marine applications as well as in large scale onshoreapplications such as combustion gas turbines for power generation. Asused in the specification and claims, the terms “essentially metal free”or “zero metals” means metals content of in range of zero to less than100 ppbwt (parts per billion) or less or a content which is so low thatit is difficult to measure reliably by conventional onlineinstrumentation.

In conventional refining, crude oil feed is cut into many pieces, andeach piece is sent down a separate market path. Opposite thereto, wehave found that we can convert a maximum amount of each barrel of crudeoil feed to a single ultraclean fuel, while capturing contaminantsulfur, nitrogen and noxious metals, save and except crude portionswhich provide process utilities and streams for such conversion andcapture. This invention cuts crude oil feed into only a minimum numberof pieces required for contaminant capture and control, then reassemblesthe pieces to form one fuel product.

Thus, this invention is unlike conventional refining which splits eachbarrel of crude feed to address multiple markets such as gasolines,diesels, fuel oils or feedstocks for downstream chemical production orapplications, processes of this invention target making just one primaryclean fuel product. This invention provides a low cost polishing systemfor crude and residual oils which is needed to make large commercialquantities of clean fuels that replace high sulfur bunker fuels andother heavy residuals used in commercial transport ships and power plantcombustion systems. This invention provides those fuels, and methods andapparatus for making such fuels, to reduce sulfur in a cost efficientmanner.

These novel processes use counter-intuitive steps to lower productioncosts, while controlling final product sulfur content at or below targetsulfur levels in a surprisingly effective manner. This inventionprovides novel methods to convert the maximum amount of each barrel ofcrude oil feed to a single ultraclean fuel, while simultaneouslycapturing contaminant sulfur, nitrogen and noxious metals during fuelproduction.

In many variations of this invention, essentially all, characterized incertain variations as ninety (90%) by volume or more of each barrel offeed is converted to such single fuel, and in such variations only aminimal amount, being less than about ten percent (10%), of each barrelof crude is consumed for process utilities and streams for suchconversion and capture of contaminants. The processes of this inventionenable adjustment of the percentage of feed allocated to fuel productand that allocated for process utilities and streams for conversion andcapture of contaminants, for purposes of hydrogen balance, local demandfor asphalt, coke and other residual products, overall productioneconomics and other operating considerations such as local availabilityof alternative lower cost process fuels and power. In variations, atleast seventy percent (70%) by volume of each barrel of crude oil feedis converted to liquid fractions, when subsequently treated or untreatedbut combined, to form substantially one liquid fuel product, notmultiple hydrocarbon products, having a sulfur content not exceeding atarget sulfur content and the remaining portion of each barrel of saidcrude oil feed is in residue or other steams or products.

Unlike conventional refining where crude oil feed is cut into manypieces, and each piece is sent down a separate market path, thisinvention cuts crude oil feed into only a minimum number of piecesrequired for contaminant capture and control, then reassembles thepieces to form one very low sulfur and nitrogen fuel product, withessentially metal free. The process and apparatus configurations of thisinvention enable low cost, efficient production of large quantities oflow sulfur fuels needed for regulatory compliance in large-scale marineand land based turbine applications. These novel fuel arrangements havesubstantially lower capital and operating costs than those ofalternative conventional crude oil refining and thereby producelarge-scale quantities of fuels having very low sulfur, very lownitrogen, and essentially metals free, in an extremely cost efficientmanner. These novel processes enable a very cost effective means tosimplify the supply chain of energy from the oil field to ship engine orland based power plant.

For the shipping industry, the novel configurations of this inventionprovide low cost, low sulfur marine fuels in quantities needed to meetworldwide marine sulfur reduction goals. The novel fuel productionmethods and apparatus arrangements of this invention have substantiallylower capital and operating costs than those of alternative conventionalcrude oil refining and thereby produce large-scale quantities of marinefuels having very low sulfur and essentially metals free, and very lownitrogen, in an extremely cost efficient manner.

The fuels of this invention replace low-grade heavy bunker oils high insulfur and metals significantly reduce open sea emissions of SOx, NOx,CO2, soot, and noxious metals. In lieu of sulfur and metals going to theenvironment upon burning bunker oil, in practice of this invention, thesulfur, nitrogen and metals are captured and removed during fuelproduction in an environment friendly manner. In some embodiments, thisinvention provides certain low sulfur alternative fuels at lower costthan diesel yet these fuels have sufficient lubricity to avoid excessivewear of ships' engines, and these novel fuels can use existing bunkeringfuel infrastructures compared to other alternatives without heating thefuel to make it flowable and hence reducing the energy consumed to heatup the fuel in tanks onshore or on the ship.

In one variation, the fuels of this invention also provide analternative to firing crude oil or heavy residuals in large land basedcombustion turbines deployed by utilities, for illustration, singlecycle or combined cycle power plants such as those producing electricityand desalinated water. Turbines firing the fuels of this invention havesignificantly less turbine exhaust gases emissions of NOx, SOx, CO2,soot, noxious metals, and other combustion byproducts, also lesscorrosion of hot zones or fouling under ash formation conditions, whenfiring a contaminated heavy crude or refinery residual oil, depending onfeed source.

This invention relates to a focused conversion of a complex hydrocarbonfeed to a single fuel product for use in combustion applications, suchas by marine engines, combustion gas turbines, or fired heaters. In abasic embodiment of this invention, crude goes in front, singleultraclean product fuel comes out back with controlled low sulfur leveland reduced nitrogen and eliminated metals. In variations, the feed todistillation can be one or more crudes, combined with one or more ofhigh sulfur fuel oils or other heavier residual oils, with addition oflight tight oils or high sulfur fuel oils, or both, as part of streamfeed to one or more of the other unit operations such as vacuumdistillation, solvent separation, hydrotreating or gasification.

In different usages in the art, the term “high sulfur fuel oil” or“HSFO” has been assigned different, often dissimilar, conflicting andconfusing means in various technical articles, patents, and statutes,some of which change over time. As used in the specification and claims,“high sulfur fuel oil” or “HSFO” means any material used as fuel havinga sulfur content in excess of 0.50% m/m (0.5 wt. %). As used herein, theterms “heavy oils”, “heavy residual oil”, “residuals”, “residue” or“other heavier oils” include petroleum derived hydrocarbonaeousmaterials having a sulfur content in excess of 0.50% m/m (0.5 wt. %).The term “high sulfur” means above the target sulfur content limit orstatutory sulfur limit where applicable, whichever is lower.

In preferred embodiments, sulfur content of final product fuel iscontrolled by combination of streams, having different sulfur content.In variations, each stream so combined is formed to interim targetsulfur content by adjusting unit operation conditions and flow rates, bytrimming addition or removal of very low sulfur streams, or by blendingfeeds of different sulfur content. Variations of this invention include,control of product sulfur levels by, optional feeding a selected crudewith one or more of (i) other crudes, (ii) bunker fuels, (iii) highsulfur fuel oils or other distillates (iv) other high sulfur or metalcontaminated residues from other sources. As used in the specificationand claims, the terms “essentially metal free” or “zero metals” meansmetals content of zero to less than 100 ppbwt (parts per billion) orless or a content which is so low that it is difficult to measurereliably by conventional online instrumentation.

We have discovered that we can optimize production of low sulfur fuelsby addressing different crude feed sulfur content distributions.

We can address (i) when only relatively small portions of sulfur inbasic H2S or RSH thiol type basic forms of sulfur are present in certainfraction and (ii) when relatively high portions of sulfur in morecomplex organic structure forms are present, and then can adjust processflow rates and operating conditions based a predicted breakpointfraction at an upper or higher level at which sulfur content begins toincrease more rapidly, maybe even exponentially, than over lowerfractional levels.

We have found we can arrange process and apparatus configurations toenable bypassing treatment of certain streams and maximize that bypass,and avoid or reduce treatment of streams containing basic less complexsulfur forms and treat streams containing more complex formsdifferently. This can include selectively excluding from hydrodesulfurization certain streams and for other streams, feed same todifferent hydrotreaters and adjust different hydrotreating unitconditions or adjust removal by solvent and/or reactive chemical basedtreatment by more than one solvents or other removal agents in one ormore removal units where each ratio of removal agents in each unit isadjusted based on sulfur distribution to each unit to selectively removeless or more complex sulfur containing molecules.

The terms “kerosene” and “light distillate” are often assigned the same,overlapping or even different meanings in different reference materialsbut are uniformly defined only based on atmospheric crude tower cutpoints of temperature intervals (such as from 190° C. to 250° C. or 180°C. to 230° C. or whatever), and are not defined based on sulfur content.Instead, convenient sulfur content measurements are taken and reportedbased on the cut point temperature intervals which are dictated byspecification for every product from a conventional refinery. We havefound that to be less than optimum.

We have discovered that we can optimize lowering costs of low sulfurfuel production if we change the basic manner in which crudedistillation towers operate. We have found that we should base certaindistillation cuts upon sulfur content of the sidestream, reflecting onthe assay of sulfur content of the crude feed or feed mix to tower, notupon standard product temperature range specifications for downstreamhistorical uses such kerosene, jet fuel, diesel or the like

We have discovered how to define “breakpoint” to address the point atwhich the change (rise over run) in sulfur content per change in unitvolume of cut produced is no longer substantially flat, but instead atthe breakpoint, as the amount of the cut is slightly increased, thesulfur content starts to rapidly increase, or increases exponentially,such as high change rate of rise over per unit run. Also at or after thebreakpoint, depending on the type of crude feed, typically the type andcomposition, as well as complexity, of the sulfur containing compoundchange. The breakpoint is a guide from separation of streams, orportions of streams, which need desulfurization from those for whichdesulfurization can be minimized or eliminated.

We found we can minimize the capital and production costs of low sulfurfuels if we maximize production of the amount total liquids having asulfur content at or below breakpoint cut so as to directly cut andcollect such maximum amount of materials having a sulfur content at orbelow the breakpoint and avoid or reduce the costs of their downstreamtreatment for sulfur reduction or removal.

We discovered that relatively large volumes of such materials at orbelow the breakpoint, and in some crudes, those portions within a narrowcertain zone above the breakpoint, will not need treatment or subsequentsignificant treatment for sulfur removal when combined with other cutswhich have been treated for sulfur removal. We maximize such productionof untreated materials to reduce overall stream desulfurization or othertreating operating costs by pushing atmospheric distillation conditions,primarily through feed or tower temperature profile increase, but alsoby reduction or elimination of reflux or reduction of crude feed rate ormix or diluting feed crude to change crude hydrocarbon or sulfurcomposition so as to maximize the amount of cuts up to near or at thebreakpoint. The breakpoint is not defined in terms of standard industryclassifications or regulations setting temperature ranges of cuts.

We define the “breakpoint”, for purposes of the specifications andclaims, in reference to an assay of crude, or other determinationmethod, as plotted with % mass or volume of crude as the x-axis, withsulfur content as the y-axis, to be the point at which sulfur contentbegins to rapidly increase from at or near horizontal, or increasesexponentially, in terms of high change rate of rise over per unit run,where delta for the run is change in unit volume of fraction and deltafor rise is change in unit of sulfur content and slope is the rise overrun. The slope of such rise over run starts from near zero orhorizontal, rapidly moves over 0.2 to quickly over 1 moves towardsomewhat exponential break out increases in sulfur content, thebreakpoint will vary based on crude or other feed to the distillationcolumn. The “breakpoint cut” or “sulfur breakpoint cut, thus addresses ameans to determine the split in hydrocarbon containing liquids, whichboil above the end point of the range for naphtha, for illustrationabove the end of range for unstabilized wild straight run naphtha, butbelow or at the breakpoint, which as noted is the point at which sulfurcontent begins to rapidly increase, or increases exponentially, in termsof high change rate of rise over per unit run.

We define base “breakpoint cut” or base “sulfur breakpoint cut” forpurposes of the specification and claims, to mean, with reference to thesulfur content of a fraction, hydrocarbon containing liquids boilingabove the end point of the range for unstabilized wild straight runnaphtha but below or at the breakpoint, where such breakpoint isselected so that when a fuel product stream is formed from combinationof all untreated streams at or below the breakpoint and all streamsabove the breakpoint cut selected to be added to such combination, thecombination fuel has an actual sulfur content that does not exceed atarget sulfur content. In variations, a fuel can be produced inaccordance wherein the target sulfur content is the sulfur breakpoint,or is higher or lower than the sulfur breakpoint, and the combination ofstreams forming the fuel are made efficiently with reference to thebreakpoint so that actual sulfur content of said fuel does not exceedthe sulfur target.

For many crudes, sulfur breakpoint cut for an atmospheric distillationcolumn would include much of kerosene range materials (which are definedin various ways in the art) such as those boiling beginning at 180° C.or 190° C. (or other kerosene range start point) and for simplification,such could include lower or higher range temperature materials. However,sulfur content, not temperature nor historical definitions of kerosenerange materials, is the determinative of the end point of the sulfurbreakpoint range. A fuel can be produced in accordance wherein thetarget sulfur content is the sulfur breakpoint, and the combination ofstreams forming the fuel are made so that actual sulfur content of saidfuel does not exceed the sulfur target.

In one embodiment, crude feed is separated into streams, one or moreliquid portions of such separate streams are treated, while otherportions are untreated. Then a majority of the volumes of all treatedand untreated liquid streams are recombined to form a liquid fuel havingan actual sulfur content at or below a target sulfur content. Processsteps comprise (a) separating the crude by one or more distillation andsolvent separation steps, into light overhead still gases, metalsenriched residue insoluble in one or more solvents used for said solventseparation, gases comprising sulfur, and liquid fractions above sulfurbreakpoint and liquid fractions at or below breakpoint, (b) treating, byone or more hydrotreating steps, liquid fractions over sulfurbreakpoint, but not liquid fractions at or below sulfur breakpoint orinsoluble residue, to form one or more hydrotreated streams havingreduced sulfur content, yet leaving other portions untreated and (c)combining said hydrotreated streams with liquid fractions at or belowbreakpoint to form said fuel having an actual sulfur content at or belowthe sulfur breakpoint as target sulfur content.

In yet a different embodiment, this invention provides a process forreducing emissions over IMO specifications by a ship at open sea, or inan ECA, or in port, by use of a fuel produced in accordance with thisinvention which has a sulfur content adjusted to less than the maximumapplicable IMO specification at the location of use of said fuel by saidship, whether at sea, or in an ECA, or in port. In this manner, a shipcan exceed IMO requirements and public expectations.

In another embodiment, this invention provides a method for ships to usethe fuels of this invention while in port to generate and sellelectricity to land based electrical grids, for example, to offset atsea or in port fuel costs.

We have discovered that we can produce a low cost ultraclean marinefuel, while considering and adjusting flashpoint in an appropriatemanner, and significantly exceed IMO expectations for limits on sulfurand metals.

We have thus discovered technical methods to trade (i) insignificantflashpoint changes for (ii) massive environmental benefits (enormous SOxand NOx reductions and essentially elimination of noxious metals)especially in relation to large quantities of fuels consumed by giganticcargo vessels. Others failed to make that discovery.

The International Convention for the Safety of Life at Sea (SOLAS)overviews fuel flashpoints and permitted use on cargo ships. “Althoughto many the 60° C. minimum flashpoint for general service fuels given inthe SOLAS Convention may seem one of the bed-rocks of marine legislationthis only came in with the 1981 amendments. The first three SOLASConventions (1914, 1929 and 1948) had placed no limit on oil fuelflashpoint and even the 1960 Convention only required that for ‘new’passenger ships that the fuel used by internal combustion engines was tohave a flashpoint of not less than 43° C.—a provision essentiallycarried over to the current 1974 Convention as originally adopted,”quoted from “Marine Distillate Oil Fuels Issues and implicationsassociated with the harmonization of the minimum flashpoint requirementfor marine distillate oil fuels with that of other users” (2012)authored by Wright et al. for the Danish Shipowners' Association byLloyd's Register FOBAS.

Wright et al. noted that flashpoint is an empirical, not real worldvalue and “flashpoint value does not, and never has, represented a‘safe’/‘unsafe’ boundary line.’ “Consequently from the outset of thepetroleum industry flashpoint has been used, somewhat incorrectly, asmeans of distinguishing between those products for which greater careand attention is required as to storage and use. In reality, in marineapplications, an oil fuel fire is initiated through leakage or pipefailures allowing the fuel to come into contact with surfaces above itsautoignition temperature rather by vapour ignition. Nevertheless,flashpoint has been used as a safety parameter in petroleum safetylegislation from the outset albeit at times against somewhat arbitrarilyset limits or due regard to the fact that it was an empirical value.

SOLAS creates an exception for cargo ships. SOLAS provides that no oilfuel with a flashpoint of less than 60° C. shall be used; except “incargo ships the use of fuel having a lower flashpoint than otherwisespecified in [SOLAS] paragraph 2.1 [e.g. 60° C.] for example crude oil,may be permitted provided that such fuel is not stored in any machineryspace and subject to the approval by the Administration.” It is notedcertain countries do not have any flashpoint standard and othercountries permit relatively low flashpoints in marine applications.

Fuel flashpoint can be adjusted by treatment, if needed. As used in thespecification and claims, the term “flashpoint treatment” means acomposition which when combined with a material increases theflashpoint. In one variation, the flashpoint treatment lower the vaporpressure of such material to which it is added to reduce risk of vaporignition. In one variation, the flashpoint adjuster is a solid or liquidadditive which has a flashpoint of 60° C. or over which is added to alow flashpoint fuel to increase the fuel's flashpoint. These can includevarious types of particulates and oils. For illustration, highflashpoint additives for treating carbon-based fuels have beendisclosed, for illustration, including U.S. Pat. No. 8,088,184 (2014) toHughes et al which discusses “high flashpoint diluents” such thoseselected from the group consisting of paraffinic base oils having aflashpoint of at least 200° C., and mixtures or combinations thereof,with specific mention of Calpar 100 (FP 210° C.), Calpar 325 (FP 240°C.), and Calpar P950 (FP 257° C.) available from Calumet Lubricants Co.of Indianapolis, Ind., and paraffinic base oils having a flashpoint ofat least 200° C., and mixtures or combinations thereof.

We have discovered technical methods to trade (i) insignificantflashpoint changes for (ii) massive environmental benefits (enormous SOxand NOx reductions and essentially elimination of noxious metals)especially in relation to large quantities of fuels consumed by giganticcargo vessels. Others failed to make that discovery.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic representation of sulfur content of various actualand hypothetical crude oils showing breakpoint ranges.

FIG. 2 is a schematic drawing of a process arrangement for treatment ofcrude oil to produce a single liquid product useful as a fuel inaccordance with this invention.

DETAILED DESCRIPTION OF THE INVENTION

In one embodiment of this invention, a process for conversion of ahydrocarbon feed, at least a portion which is crude oil comprisingsulfur and metals, to a single liquid product comprises (i) separatingsaid feed by one or more distillation and solvent separation steps, intolight overhead still gases (which can include only still gases notcondensable at atmospheric distillation conditions as per EIA definitionor more, whether or not a debutanizer systems is preferred for specificlocal considerations or its costs to be eliminated in other situations),metals enriched residue insoluble in one or more solvents used for saidsolvent separation, gases comprising sulfur, and liquid fractions,comprising sulfur, which comprise distillate (with at least some portionof kerosene range materials for some feeds being treated as withindistillate range) and vacuum gas oil range hydrocarbons, (ii)hydrotreating, by one or more hydrotreating steps, selected liquidfractions over sulfur breakpoint cut (where preferably only solubleliquid fractions are selected for hydrotreating), but not liquidfractions at or below sulfur breakpoint cut (and preferably not thoseportions of any fractions which are insoluble in said solvents used insolvent separation), to form one or more treated streams having reducedsulfur content, (iii) combining said untreated fractions with saidtreated streams to form a fuel having an actual sulfur content at orbelow a target sulfur content. As used herein, the term “steps” or“zone” can refer to a unit operation or area having one or more processoperations having equipment configurations and/or one or more segmentsof a unit operation or a sub-zone. Equipment items can comprise one ormore tanks, vessels, distillation columns, separators, reactors orreactor vessels, heaters, exchangers, strippers, pipes, pumps,compressors, and controllers. In preferred variations of this invention,substantially all hydrocarbon compositions of said feed are separatedinto fractions but are subsequently recombined to form said fuel whichis one liquid fuel product comprising a range of hydrocarbons fromoriginal feed liquefied petroleum gas, or in one variation, naphtha tohydrotreated deasphalted oil and is not multiple hydrocarbon products,except hydrocarbon compositions comprising those within (i) lighteroverhead gases of distillation, (ii) said residue insolubles and (iii)streams for sulfur or metals recovery. Such range is substantially theentire range of crude oil derived hydrocarbons from C3 or C5 to greaterthan C20, said hydrocarbons having an initial boiling point being thelowest boiling point of any fraction within untreated streams combinedin said fuel and highest boiling point being the highest boiling pointof a treated stream combined in said fuel. The term “untreated” as usedin the specifications and claims means not subjected to hydrotreating toreduce or remove sulfur, nitrogen or metals. In one variation, such fuelcomprises substantially a range of crude derived hydrocarbons from C3 orC5 to greater than C20 or those comprising those having an initialboiling point in the range about 35° C. to about 315° C. and higher,preferably up to the initial boiling point of the end of deasphalted oiland start of deasphalted residue, which is not soluble in solventselected for solvent separation. In still more preferred variations, afuel of this invention comprises a combination of hydrocarbons rangingfrom the lowest boiling portion of said untreated liquid fraction fromatmospheric distillation to highest boiling portion of hydrotreatedsolubles from solvent separation. Thus, preferred fuel of this inventionis opposite to conventional gasolines, diesels, kerosenes, and fuelsoils which have been cut into select sub-ranges and do not havemeaningful content of full ranges of such hydrocarbons. Thus oneembodiment of this invention is a fuel derived as a single product ofprocessing crude oil, said fuel having an actual sulfur content of 0.5wt. % or less, preferably 0.1 wt. % or less, comprising thesubstantially the entire range of crude oil derived hydrocarbons from C3or C5 to greater than C20, said hydrocarbons having an initial boilingpoint being the lowest boiling point of any fraction of said crude oilat atmospheric distillation conditions and highest boiling point beingthe final boiling point of the residual portion of said crude oil whichis not soluble in a solvent suitable for solvent separation. Invariation, such fuel comprises substantially the entire range of crudeoil derived hydrocarbons from C3 or C5 to greater than C20, saidhydrocarbons having an initial boiling point being the lowest boilingpoint of any fraction within untreated streams combined in said fuel andfinal boiling point being the highest boiling point of a treated streamcombined in said fuel. In one variation, crude is separated into lightoverhead still gases, metals enriched residue insoluble in one or moresolvents used for said solvent separation, gases comprising sulfur(including purge gases comprising sulfur), and liquid fractionscomprising sulfur comprising (i) liquid fractions at or below sulfurbreakpoint and (ii) liquid fractions over sulfur breakpoint, which areeither soluble or not soluble in solvent used in solvent separation (b)hydrotreated, by one or more hydrotreating steps, said soluble liquidfractions over sulfur breakpoint, but not liquid fractions at or belowsulfur breakpoint or insoluble fractions, to form one or more treatedstreams having reduced sulfur content, (c) combining said untreatedfractions with said treated streams to form a fuel having an actualsulfur content at or below a target sulfur content.

In variations, such residue is fired in one or more gasifiers forgeneration of electricity and at least a portion of hydrogen for saidhydrotreating and for capture at least a portion of said metals ingasifier solids which are removed or the residue is fired in one or moreboilers having flue gas sulfur and metals capture, for generation ofelectricity and an ancillary hydrogen generation unit operations forsupply of hydrogen for said hydrotreating. Preferably and all gasescomprising sulfur are directed to one or more common sulfur recoveryunits.

By practice of this invention, the actual sulfur content of said fuelcan be adjusted to meet a target sulfur content limit specification, forexample an IMO specification for a marine fuel or a sulfur limit forcombustion gas turbine, by adjusting the amount of continuous flow ofuntreated and treated streams to the combination forming the fuel. Forillustration, the target sulfur content of fuel can be adjusted to meetone or more target IMO specifications, for within or outside an ECA, forexample, selected from 3.5 wt. %, 0.5 wt. %, 0.1 wt. % or other IMOspecification. A fuel produced in accordance with the processes of thisinvention is useful in marine engines, combustion gas turbines, firedheaters such as boilers and other applications.

In one variation, at least one of said hydrotreated streams is anultralow sulfur stream having 10 ppmwt or less of sulfur which is usedto adjust, by reduction or addition of the amount of such stream to saidcombination, formation of said fuel having an actual sulfur content ator below a target sulfur content. In another variation, when at leastone of the hydrotreated steams is an ultralow sulfur stream having lessthan 10 ppmwt of sulfur, and the untreated fraction has a sulfur contentin excess of the target sulfur content and the untreated fraction isused as trim control, by reduction or addition of the amount of suchuntreated fraction to said combination, to form a fuel having an actualsulfur content at or below a target sulfur content. In yet anothervariation, wherein a crude oil feed is converted to substantially oneliquid fuel product, not multiple hydrocarbon products, a firsthydrotreated stream is produced which is a reduced sulfur stream havinga sulfur content less than 10 ppmwt of sulfur, and a second hydrotreatedfuel fractions is produced which has a reduced sulfur stream having asulfur content in the range of 0.12 to 0.18 wt. % sulfur, and theuntreated fraction has a sulfur content, either at or below or above thebreakpoint sulfur, in excess of the target sulfur content and eithersaid first hydrotreated stream or second hydrotreated stream, or both,are used as trim control, by reduction or addition of the amount of suchsteams to said combination, to form a fuel having an actual sulfurcontent at or below a target sulfur content.

In still more preferred embodiments, the sulfur contents of the one ormore crude, residual oil and others feeds are selected, or processingconditions are adjusted, to where at least 70% by volume of each barrelof said crude oil feed is converted to liquid fractions, whensubsequently treated or untreated but combined, form the product fuelhaving sulfur not exceeding a target sulfur content not multiplehydrocarbon products, having a sulfur content not exceeding a targetsulfur content and no more than 30% of each barrel of said crude oilfeed is directed to other than the fuel. In preferred variations of thisinvention, at least 80% by volume of each barrel feed, and morepreferably near 90% or more of feed depending on feed composition,hydrogen balances, process economics and other factors, as well asadjustment of process operating conditions and flow rates, of eachbarrel of hydrocarbonaeous feed is converted to one liquid fuel product,not multiple hydrocarbon products, except one or more very low sulfurstreams that are used as trim to control, by increasing or decreasingtrim flow, the final fuel product sulfur content to a level notexceeding target sulfur content. Excess amounts of a trim stream can beseparately transferred for material balance and inventory controlpurposes. In such preferred variations of this invention, no more thanabout 10% to 30% by volume of each barrel of said crude oil feed iscaptured in metal enriched residue, post atmospheric and vacuumdistillation via solvent extraction.

In another variation, a high sulfur fuel oil having a sulfur contentgreater than the target sulfur content is added, either alone or with alight tight oil, before or during combining all treated and untreatedfractions to form said fuel. Said high sulfur fuel oil can be fed to oneor more of said distillation step, solvent separation step orhydrotreating step. In one preferred embodiment, an ultralow sulfurstream has in the range of less then 10 ppmwt or less of sulfur, and theuntreated fraction has a sulfur content in excess of the target sulfurcontent and said untreated fraction is used to adjust, by reduction oraddition of the amount of such untreated fraction to said combination,to form the product fuel having an actual sulfur content at or below atarget sulfur content.

The apparatus for practice of the process of this invention can have areduced equipment footprint, in the range of 20% to 30% the apparatusfootprint of conventional refinery that has typical downstreamprocessing units. Thus capital costs per barrel of feed treated aresubstantially reduced. For example, one specific embodiment of thisinvention employs only one or more of atmospheric distillation, vacuumdistillation, solvent separation, hydrotreating and gasification, withrequired ancillary apparatus for capture of sulfur and metals and do nothave any hydrocarbon treating operations downstream of hydrotreatingexcept gasification with required ancillary apparatus for capture ofsulfur and metals.

Variations of process configurations of this invention provide highefficiency, low cost operation by effective integration of a utilityisland to supply process needs for hydrogen, steam, and fuel gas, aswell as electricity, while also providing integrated metals and sulfurcapture means. The utility island comprises one or more gasifier systemstreat heavy metals enriched residue to capture and eliminate metalscontaminants as a component of potential air emission sources andpreferably use an integrated, thus lower capital cost, off gas treatmentof sour gas and acid gas from all sources for sulfur capture, treatmentand removal as potential emission sources. The island configuration ofthis invention produces hydrogen for hydrotreating steps, steam and fuelgas for process electrical and the process electrical via a highefficiency combined cycle power generation means utilizing certainstreams, that would otherwise be waste streams, to fulfill processrequirements.

One variation of this embodiment of this invention addresses when alight tight oil does not contain sufficient heavier hydrocarbons withinits bottoms fractions and residuals to providing processing balance forhydrocarbon treatment and corresponding hydrogen generation to enableprocessing such light crude to hydrogenate to lower sulfur and metalsfor decontamination. This method includes the step of adding said lightcrude, either separately or mixed with other feeds, to any or all of theheavier feeds to atmospheric distillation, vacuum distillation orsolvent separation of treatments.

In one variation, designs for apparatus for vacuum distillation, solventseparation, hydrotreating and gasification operations downstream ofatmospheric distillation are sized to have added or spare capability toprocess high sulfur fuel oil or additional heavier residue sourced froma different source outside the battery limits of said operations to forma fuel having an actual sulfur content at or below a target fuel sulfurcontent limit level and capture at least a portion of the sulfur andmetals from said additional heavy residue.

In another embodiment, this invention provides a method for ships to usethe fuels of this invention while in port to reduce local emissions, aswell as generate and sell electricity to land based electrical grids. Inone variation, this invention provides a technical method for reducingemissions at or near locations of ports comprising (a) technicalanalysis to ascertain per kilowatt per hour (KWH) amount of sulfur ormetals emissions results from on-shore generation facilities thatgenerate electricity normally supplied to the electrical grid at or nearlocation of port (including for illustrations, emissions associated useof local electrical supply by a ship when in port and connected to suchgrid) and (b) technical analysis to ascertain per KWH amount of sulfuror metals emissions resulting from on-board ship electricity generationby the same ship when in port at the location of (a), then compare (a)and (b) and if (b) emissions generated by the ship for electricitygeneration are lower than local sources of power of (a), then emissionsare reduced in the ship tender all or portion of on-board electricitygeneration to the grid. This embodiment may be particularly useful toreduce environmental emissions when locally supplied electricity is fromcertain types of coal fired sources or heavy crude or residual oils areused to fire electricity generation, where options for lower emissionsare not available for local electrical generation. Absent offsets, suchtender by ship to local grid would likely not be made if KWH cost ofship generated power is more than KWH cost of local grid power or ifsuch tender by ship to local grid is otherwise not profitable to theship, save and except an offset of port fees or other unless offset byemissions reduction credit such as a subsidy to pay for low emissionpower generation.

If the tender by the ship to local grid is profitable, then the ship canoffset or reduce fuel costs incurred while at sea via revenues generatedby tender to grid on shore while in port of all or portion of on-boardelectricity generated by use a fuel of this invention while in port.Such revenue generated by tender to grid while at port can offset voyageat sea fuel costs to a level that could lead to actual voyage at seafuel costs with these novel fuels being lower than costs of high sulfurfuel oil for voyage at sea, depending on stop duration at port.

FIG. 1 is a schematic of a plot of sulfur content of various actual andhypothetical crude oils showing breakpoint ranges. The exemplary crudesulfur profiles 4,5,6 are plotted based on center points of actual dataextracted from publication entitled Sulfur Compounds in Crude Oil,Washington D.C., published by UNT by Rall et al. The crude sulfurhypothetical profiles 1,2,3 are derived in part from actual data adaptedfrom various sources, including Petroleum Refining, Crude Oil PetroleumProducts Process Flowsheets (1995) by J.P. Wauquier, published byInstitut Francais du Petrole.

FIG. 1 illustrates how to suggest a “breakpoint” definition fordifferent crudes for the process configurations of this invention. FIG.1 is illustrative of breakpoints is the point at which the change (riseover run) in sulfur content per change in unit volume of cut produced isno longer substantially horizontal or flat, but instead at thebreakpoint, as the amount of the cut is slightly increased, the sulfurcontent starts to rapidly increase, or increases exponentially, to causea high change in rate of rise over per unit run. Also at or after thebreakpoint, depending on the type of crude feed, the type andcomposition, as well as complexity, of the sulfur containing compoundschange. The breakpoint enables determination, for operating efficiency,of how best to bypass cost intensive hydrotreating, yet produce fuelsmeeting target sulfur content limit specifications. That is breakpointcan be the maximum sulfur content of atmospheric crude tower fractionwhich is directed away from, or reduced from, further downstreamprocessing to reduce sulfur content, such as being directed away fromhydrotreating. Fractions above the breakpoint are directed to downstreamprocessing to reduce sulfur content while the fractions at or below thebreakpoint are untreated, resulting in substantial operations savings.In conventional refining, cuts are fixed by temperature ranges, notsulfur content. The target sulfur content, for illustration an end userequirement, can determine selection of the breakpoint. If breakpoint isset too high, then excessive flows of higher sulfur untreated streamscannot be offset readily by increased flows of lower sulfur hydrotreatedstreams.

FIG. 2 gives a general overview of another embodiment of this inventionand shows in simplified form the major components of process operationfor production of a single liquid product suitable for use as a fuel.FIG. 2 shows a process for integration of atmospheric and vacuumdistillation, solvent separation, hydrotreating and gasification toproduce a single low sulfur, essentially metals free fuel product.

A stream of contaminated crude oil comprising sulfur, nitrogen andmetals enters the process via line 2 after pretreatment such asdesalting, which is preferred for crude oil. In this example, the crudefeed 2 can be a single crude oil or blends of one or more crude oils ora blend of a crude oil with a residual oil such as high sulfur fuel oil.The feed 2 is directed to an atmospheric distillation column 100, wherethe feed is separated into light overhead gases 4 and multiple cuts. Thelight overhead gases 4 include non-condensable still gases 6 useful asprocess fuels or can be captured for other uses. In one preferredvariation, capital expenditures associated with a stabilization systemare avoided with respect such overhead gases 4; however, depending onlocal needs, for example a special marine fuel maximum H2Sspecification, a stabilization system can be included. In an embodimentshown in FIG. 2, the multiple cuts would include one or more of streamswithin these ranges (1) unstabilized wild straight run naphtha via line4 at line 16, (2) sulfur breakpoint cut at line 18, (3) light distillateat line 24, (4) medium distillate at line 26, (5) a first heavydistillate at line 28, (6) atmospheric residual at line 30.

In different usages in the art, different meanings have assigned to thesame or similar cuts in different regions of the world, which meaningsare often dissimilar, overlapping, conflicting and confusing means. Asused in the specification and claims, the following means are assigned:(a) “naphtha” means carbon containing compositions ranging from thosehaving a minimum of three (3) carbons C3 such as propane to those havingan initial boiling point (IBP) of about 175° C. (about 350° F.), withoutlighter boiling compounds, such as methane or lighter, (b) “stabilizednaphtha” means, as such pertains to naphtha or other naphtha rangematerials used as a fuel blend stock, that lighter boiling compounds,such as butane or propane or lighter, have been almost completelyremoved from the naphtha or fuel, where for illustration, in aconventional refinery, the bottoms stream from a naphtha debutanizerdistillation tower would be a stabilized naphtha, (c) “unstabilizednaphtha” means naphtha which has not had the C4 or lighter componentsremoved; for illustration, in a conventional refinery, the feed streamto a naphtha debutanizer would be an unstabilized naphtha, (d)“unstabilized wild straight run naphtha” means carbon containingcompositions recovered from atmospheric distillation ranging from thosehaving a minimum of three (3) carbons C3 such as propane up to thosehaving an initial boiling point (IBP) of about 175° C. (about 350° F.),without lighter boiling compounds, such as methane or lighter, of whichatmospheric distillation overhead still gases may be comprised, (e)“wild naphtha”, in the context of hydrotreating, means the unstabilizedlighter fraction of hydrotreater effluent recovered from a fractionator,or other separator, operability considered a portion of a hydrotreatingzone which recovers one or more heavier fractions at or near separatorbottoms, such as distillate range, heavy oil range, or other heavierthan naphtha portion of the feed to the separator and unstabilized, (f)“breakpoint cut” is defined herein above in this specification and anexample is shown in FIG. 1, (g) “light distillate over breakpoint cut”or “light distillate” herein the fraction having an initial sulfurcontent over the highest sulfur content of the breakpoint cut, whichcorrespondingly has an boiling point (IBP) of over the highest finalboiling point of the breakpoint cut, (h) “medium distilliate” means afraction between light distillate and heavy distillate, separated as cutbased on preferred distillation column design; where for example, mediumdistillate cut could be eliminated and combined with either lightdistillate or heavy distillate, (i) “first heavy distillate” means theheaviest fraction of an atmospheric distillation unit, the sulfurcontent and boiling point range of which are determined by operatingfactors such as one or more of sulfur composition of distillation unitfeed, crude tower operations severity and downstream hydrotreatingconditions, (j) “first heavy distillate” means the heaviest fraction ofan atmospheric distillation unit, having a sulfur content and boilingpoint range which are determined in reference to sulfur composition ofdistillation unit feed and the sulfur breakpoint cut and by reference toone or more operating factors such as crude tower operations severityand severity of downstream distillate hydrotreating conditions, (k)“second heavy distillate” means the lightest fraction of a vacuumdistillation tower having a sulfur content and boiling point range whichare determined in reference to sulfur composition of distillation unitfeed and the sulfur breakpoint cut and by reference to one or moreoperating factors such as crude tower operations severity and severityof downstream distillate hydrotreating conditions, and (j) “atmosphericresidual”, “vacuum residual”, “vacuum gas oil” including “light vacuumgas oil” and “heavy vacuum gas oil”, “solvent separation” and“hydrotreating” and other terms, and variations in such terms, are knownto those skilled in the art of processing crude oil.

Preferably, the combination of steams (1) unstabilized wild straight runnaphtha via line 4 at line 16 and (2) sulfur breakpoint cut at line 18would contain in the range of less than 0.06 wt. % sulfur to 0.08 wt. %sulfur if the fuel combination at 600 target sulfur content is 0.1 wt. %or less sulfur and treated stream 70 sulfur content is less than 10ppmwt, where flow rates of steams 10 and 70 the combination are adjustedso that the fuel combination 600 does not exceed target sulfur content.

In FIG. 2, the atmospheric residual is fed via line 30 to a vacuumdistillation tower 200 to produce (1) a second heavy distillate at line32, (2) light vacuum gas oil at line 36, (3) heavy vacuum gas oil atline 38 and (4) vacuum residual at line 50. The vacuum residual isdirected via line 50 to solvent separation 300 to produce (1)deasphalted oil at line 80 and a pitch, being pitch, which is a metalsrich heavy residual at line 90.

FIG. 2 shows an integrated hydrotreater system 400 comprising twohydrotreating zones, a distillate hydrotreater zone 430 and a heavy oilhydrotreater zone 460. Integrated hydrogen treatment systems are knownin the art, and are preferred for this application; however, mildhydrotreating conditions of relatively low pressures in the range ofabout 117 bar to 138 (1700 to 2000 psi) are sufficient forhydro-desulfurization and hydro-demetalization in both zones 430 and460.

The light distillate 24, medium distillate 26, first heavy distillate 28and second heavy distillate 32 are preferably fed to an integratedhydrotreater system 400 and treated with hydrogen in presence ofcatalyst at hydrotreating conditions to form distillate hydrotreaterzone 430 effluent streams in line 60. Such hydrotreater effluent 60comprises materials within ranges of (1) wild naphtha, with anticipatedboiling range from above C5 (five carbons containing compositions) toabout 175° C. (about 350° F.) and (2) ultra low sulfur diesel,preferably having a sulfur content of less than 10 ppmwt, being areduced sulfur stream formed from combination of treated distillatesteams comprising light distillate 24, medium distillate 26, first heavydistillate 28 and second heavy distillate 32. Those skilling inhydrotreating art understand that byproducts of hydrotreating in zone430 may include gases containing sulfur such as hydrogen sulfide,hydrogen rich off gas, at least a portion of which is treated for sulfurremoval and is recycled as hydrogen addition to either distillatehydrotreater zone 430 or heavy oil hydrotreater zone 460, or both, and atypically a minor amount of liquid petroleum gases.

The light vacuum gas oil 36, heavy vacuum gas oil 38 and deasphalted oil80 are are preferably also fed to the integrated hydrotreater system 400and treated with hydrogen in presence of catalyst at hydrotreatingconditions to form heavy vacuum gas oil hydrotreated zone 460 effluentstreams 70. Such hydrotreater effluent comprises materials within rangesof (1) wild naphtha, with anticipated boiling range from above C5 (fivecarbons containing compositions) to about 175° C. (about 350° F.) and(2) ultra low sulfur diesel, preferably having a sulfur content of lessthan 10 ppmwt, being a first heavy oil hydrotreating zone reduced sulfurstream formed from a first portion of the combination of treateddistillate steams comprising light vacuum gas oil 36, heavy vacuum gasoil 38 and deasphalted oil 80, (3) a second reduced sulfur stream,preferably having a sulfur content in the range of 0.12 to 0.18 wt. %sulfur, being formed from a second portion of the combination of treateddistillate steams comprising light vacuum gas oil 36, heavy vacuum gasoil 38 and deasphalted oil 80. Those skilling in hydrotreating artunderstand that byproducts of hydrotreating in zone 460 may includegases containing sulfur gases such as hydrogen sulfide, hydrogen richoff gas, at least a portion of which is treated for sulfur removal andis recycled as hydrogen addition to either distillate hydrotreater zone430 or heavy oil hydrotreater zone 460, or both, and a typically a minoramount of liquid petroleum gases.

Untreated stream 10 and one or more the hydrotreated liquid streams vialine 60 and line 70 are combined to form low sulfur essentially metalsfree fuel product at 600, where ‘combine’ means formed by in-line streammixing, blending, or other intimate combination. In one variation,unstabilized wild straight run naphtha via 4 and 16 and sulfurbreakpoint cut via 18 are combined in 100 without added treatment, thenform fuel combination at 600 by combination with one or more of theeffluents from the distillate hydrotreater zone 430 comprising wildnaphtha and ultra low sulfur diesel and with one or more of effluentsfrom heavy oil hydrotreater zone 460 comprising wild naphtha, ultra lowsulfur diesel and a second reduced sulfur stream which is formed in theheavy oil hydrotreater zone 460. In another variation, with thehydrotreating zone 400, the effluents of zone 430 and 460 are combinedto form a single stream as if line 60 and line 70 were combined (notshown) within such zone, with such variation being useful whereseparation of effluent of hydrotreaters 430 and 460 is not preferred.Preferably, the vacuum gas oil hydrotreating portion 460 has overheadsystem flow and bottom system flow, a portion which flows are a dieselboiling range material, that may be a relatively small amount comparedto combined diesel contributed by zones 430 or 460 to the combination600 and the combined diesel side hydrotreating portion 430 also have awild naphtha side stream, either alone or part of an overhead systemflow and bottom system flow including low sulfur diesel directed toblock 600 or used as trim or other purposes.

The deasphalter 300 bottoms heavy residual 90 comprising asphalt andmetals rich heavy residual is fed to an integrated gasification-combinedcycle system 500 comprising one or more gasifiers for partial oxidationof said heavy residual 90 in presence of steam and oxygen and optionallycarbon containing slurry quench, to form syngas, at least a portion ofwhich is converted to hydrogen which is directed via line 502 for use inhydrotreater system 400 comprising distillate hydrotreater 430 and heavyoil hydrotreater 460 and syngas for firing a gas turbine of a combinedcycle power unit within the gasification system 500 for electricalgeneration within 504 for process uses and other uses, and hot turbinegas, and also comprising a heat recovery generator to recover heat fromhot gas turbine gas to produce steam which drives a steam turbine, foradditional electricity generation directed as power via 504. Eachgasifier also produces metals rich soot, which may be in the form ofparticulate solids, which comprises metal contaminants derived from thecrude and/or heavy feeds, which solids are directed via line 506 fromeach gasifier for metals removal. Support systems comprise one or moregas treatment units to which all sulfur containing gas streams, whethersour gas or acid gas, from all unit operations are fed for sulfurremoval via 508. Preferably such sulfur removal systems are part of theutilities island of which the gasification system is part. Morepreferably, one or more sulfur containing gas streams are directed tocommercial sulfur acid production as part of overall sulfur removal. Thegasification system 500 will typically include acid gas removal unit andsour CO-shift system that are optimized in capacity and configuration toproduce the required hydrogen from at least a part of the raw syngasproduced within the gasification system.

In the integrated hydrotreating system 400 variation shown by FIG. 2,make-up hydrogen containing gas 502 from gasification system 500 inquantities required for hydrotreating, along within internal recyclehydrogen within the hydrotreating block 400, is compressed and heated toeffective hydrotreating operating temperatures, pressures, spacevelocities and pressures, which are adjusted based upon catalystselected and other conditions as known in the art to achieve desiredlevel of desulfurization and demetalization. Such prepared hydrogen 502(along with recycle hydrogen) is deployed first in the heavy oilhydrotreater zone 460, the higher pressure zone. The effluent of theheavy oil hydrotreater zone 460 comprising hydrotreated liquids and ahydrogen containing gas are separated in a high pressure separator (notshown), with such liquids being collected within zone 460 and thehydrogen containing is recovered and passed via line 410 to thedistillate hydrotreater 430 for hydrotreating use in such lower pressurezone. Hydrotreated liquids and purge gases comprising sour and acidgases from hydrotreater zone 430 are passed via line 412 to heavy oilhydrotreater zone 460, where such are substantially combined. Thehydrotreated treated liquids of both zones 430 and 460 can be 430 and460 can be segregated via lines 60 and 70 and separately used as inputsto the combination fuel 600 or be added as trim to control combinationzone 600 sulfur level or be withdrawn (not shown), depending on processsulfur and material balance needs. In the integrated hydrotreatingvariation shown, the purge gases 420 of both zones 430 and 460 aredirected via line 420 to utilities island 500 comprising sulfur recoverysystems and optionally, gasification or boilers.

Not shown in FIG. 2, but known to those skilled in the hydrotreatingart, are various ancillary high, medium and low pressure gas-liquidseparators, stream heaters, gas recycle and purge lines, reflux drumsfor gases or lights and liquid separation, compressors, cooling systems,and other ancillary application. Also, if not within a common utilitiesisland but instead are located within the hydrotreating zone, variousamine or other sulfur recovery agent absorbers and stripping systems forsour gas or acid gas treatment would be included in hydrotreating zone400.

Parameters for selection of hydrotreating catalyst and adjustment ofprocess conditions of hydrotreating zone 400 are within the skill of aperson engaged in the petroleum refining industry and should not requireadditional explanation for practice of the hydrotreating segments ofthis invention. In the reaction zones of the distillate hydrotreater 430and the heavy oil hydrotreater 460 the hydrotreating catalysts employedinclude any catalyst composition useful catalyze the hydrogenation of ahydrocarbon feed to increase its hydrogen content and/or remove sulfur,nitrogen, oxygen, phosphorus, and metal heteroatom contaminants.Specific catalyst types and various layer configurations used andhydrotreating conditions selected will depend on the hydrocarboncomposition, as well as sulfur and metals content and heavy carbonresidue, of each feeds being processed by each respective unit, thedesired reduced sulfur and metals content of the product stream fromeach zone. Such catalyst may be selected from any catalyst useful forthe hydrotreating of a hydrocarbon feedstock; however, operatingconditions are adjusted to avoid or minimize ring saturation orhydroconversion in the practice of preferred embodiments of thisinvention. Publication number US20140221713A1 (U.S. Ser. No. 13/758,429)2014 by Baldassari et al, which is incorporated herein by referencedescribes various suitable hydrotreating catalyst as well suitablehydrotreating processes including variations of integrated hydrotreatingapparatus. Baldassari et al further summaries variations of catalystcompositions and condition ranges for distillate and heavy oilhydrotreating and distinguish over conditions for hydrocracking and forresidue hydroconversion, all of which are known those skilled in the artof hydroprocessing. “Revamping Diesel Hydrotreaters For Ultra-Low SulfurUsing IsoTherming Technology” by Ackerson et al discusses unit design,catalyst choices, hydrogen consumption, and other operating conditionsfor sulfur removal by hydrogenation to produce a product containing lessthan 8 ppm sulfur by use of a high activity Ni/Mo catalyst. “OptimizingHydroprocessing Catalyst Systems for Hydrocracking and DieselHydrotreating Applications, Flexibility Through Catalyst” by Shiflet etal, page 6 Advanced Refining Technologies Catalagram Special EditionIssue No. 113/2013 also discusses hydroprocessing to 10 ppm or lesslevels using high activity CoMo catalyst to remove unhindered sulfur anda high activity NiMo catalyst for remaining sterically hindered sulfur.

In another variation illustrated by FIG. 2, sulfur content of feed 2 ismeasured by an assay which indicates the sulfur profile exponentialbreakpoint and rate of rise, for illustration a breakpoint of sulfurcontent in the range of 0.06 to 0.08 wt. % (or higher based onconsiderations of relative flow rates of untreated and hydrotreatedsteams and their respective sulfur contents) and use such profile tocontrol adjustments to atmospheric distillation 100 to maximize theavailable amount of unstabilized wild straight run naphtha 16 and sulfurbreakpoint cut 18 which can flow to combining by flow mixing or byblending at the product collection zone 600 available be withouttreatment and determine, or reduce if needed, the amount of (1) streamsof light distillate 24, medium distillate 26, first heavy distillate 28or second heavy distillate 32 to the distillate hydrotreater zone 430,or (2) streams light vacuum gas oil 36, heavy vacuum gas oil 38 ordeasphalted oil 80 to heavy oil hydrotreater 460, which flows aredirected to hydrotreating, in an increased or decreased amount fortreatment to form a fuel product 600 having an actual sulfur content ator below a target sulfur content limit level. In yet another variation,the assay can be used to control the maximum amount of streams otherthan untreated unstabilized wild straight run naphtha 16 and untreatedsulfur breakpoint cut 18 to determine the amount of streams to bedirected to hydrotreating to form a fuel 600 having an actual sulfurcontent at or below a target sulfur content limit level. That is, thevarious rates of flow to hydrotreating 400 of any of amounts of (1)streams of light distillate 24, medium distillate 26, first heavydistillate 28 or second heavy distillate 32 to the distillatehydrotreater zone 430, or (2) streams light vacuum gas oil 36, heavyvacuum gas oil 38 or deasphalted oil 80 to heavy oil hydrotreater 460,can be increased or decreased amount to cause adjustment of sulfurcontent hydrotreating zone 400 effluents 60 or 70, or both, which iscombined at 600 with untreated streams of 10.

In one variation, fuel product 600 having an actual sulfur content at orbelow a target sulfur content limit level is formed by adjustment offinal actual product 600 sulfur level by increasing or decreasingamounts to combination zone 600 one or more of any of (a) unstabilizedwild straight run naphtha 16 or sulfur breakpoint cut 18, each of whichmay contain some sulfur content because they are not treated for sulfurremoval or (b) streams to or from distillate hydrotreater 430 such asthose of treated light distillate 24, medium distillate 26, first heavydistillate 28 and second heavy distillate 32, or (c) streams to or fromheavy oil hydrotreater such as those of treated light vacuum gas oil 36,heavy vacuum gas oil 38 and deasphalted oil 80, where such adjustment isbased upon measurement of relative sulfur content contribution of eachstream 60 or 70 to the combination 600.

In one embodiment, light tight oil or condensate, or a combination oflight tight oil or the like such as non-associated gas and shale gasproduction condensate, having low metals content and a sulfur contentless than the target sulfur content limit level for the fuel 600 iscombined with one or more of (a) feeds to atmospheric distillation 100or vacuum distillation 200, solvent separation 300, any of the feeds oflight distillate 24, medium distillate 26, first heavy distillate 28 orsecond heavy distillate 32 to the distillate hydrotreater 430 or any ofthe feeds of light vacuum gas oil 36, heavy vacuum gas oil 38 ordeasphalted oil 80 to heavy oil hydrotreater 460 to the heavy oilhydrotreater, or (b) stream 10 formed from unstabilized wild straightrun naphtha 16 and sulfur breakpoint cut 18, without added treatment or(c) stream formed from distillate hydrotreater comprising wild naphthaand ultra low sulfur diesel, or (d) streams formed from heavy oilhydrotreater comprising wild naphtha, ultra low sulfur diesel and asecond reduced sulfur stream or (e) combined effluent 70 of thehydrotreating unit 400 directed to the finished product fuel 600 or (f)otherwise added to a facility produced fuel within or outside the fenceof the facility producing such fuel to form a finished product fuel.

In one variation shown in FIG. 2, the fuel product 600 sulfur content iscontrolled to be at or below a target sulfur content limit level by (a)feeding to the combination 600 unstabilized wild straight run naphtha 16and sulfur breakpoint cut 18, without added treatment of either suchstream via line 10, then (b) adjusting actual product sulfur level 600by increasing or decreasing amounts to the combination of one or more ofany of (1) streams of light distillate 24, medium distillate 26, firstheavy distillate 28 or second heavy distillate 32 to the distillatehydrotreater zone 430, or (2) streams light vacuum gas oil 36, heavyvacuum gas oil 38 or deasphalted oil 80 to heavy oil hydrotreater 460,and (c) then decreasing amounts to the combination of one or more of anyof (1) streams from distillate hydrotreater zone 430 via line 60 whichwas formed from light distillate 24, medium distillate 26, first heavydistillate 28 or second heavy distillate 32, (2) streams from heavy oilhydrotreater zone 460 via line 70 which was formed from light vacuum gasoil 36, heavy vacuum gas oil 38 and deasphalted oil 80, if any or all ofsuch needed for any reason to increase the actual product 600 sulfurlevel to the target sulfur level, or (d) increasing amounts to thecombination of one or more of any of (1) said streams from distillatehydrotreater 430 via line 60 or (2) streams from heavy oil hydrotreater460 via line 70, if needed for any reason to decrease the actual product600 sulfur content at or below the target sulfur content limit level.Multiple sulfur grades can be efficiently produced due to suchfacilitation, for example those fueled targeted for 500 ppmwt or lesssulfur fuel for marine and land based gas turbines or differing rangesfor the same applications at different locations requiring differenttarget sulfur contents.

In variations for use of high sulfur fuel oil having a sulfur contentgreater than the target sulfur content limit level of finished fuel atcombination 600, the high sulfur fuel oil is fed as part of one or moreof the various feeds to one or more of each unit operation. High sulfurfuel oil can be added to (a) feed line 2 to atmospheric distillation 100or line 30 to vacuum distillation 200, or (b) line 50 solvent separation300, or (c) line 20 to distillate hydrotreater 430, either separately orcombined with one or more of light distillate 24, medium distillate 26,first heavy distillate 26 or second heavy distillate 32 feeds to saiddistillate hydrotreater 430, or (d) line 40 to heavy oil hydrotreater460, either separately or combined with one or more of light vacuum gasoil 36, heavy vacuum gas oil 38 and deasphalted oil 80, to form a fuelcombination 600 having an actual sulfur content at or below a targetsulfur content limit level. Those skilled in the refining art understandthat in practice of one or more of these variations regarding use of ahigh sulfur fuel oil as feed and and selection of its point of feed,consideration will be given to its sulfur content, asphaltene contentand other factors pertaining to nature of the high sulfur fuel oil feedand compatibility with co-processed crude or other feeds, vessel spaceand energy consumption, asphaltene content, content of undissolvedcomponents, gum formation, and other efficiency issues.

In another variation, a clean fuel at combination 600 zone is formed byadding a high sulfur fuel oil, which can have a sulfur content greaterthan the target sulfur content limit level to one or more of (a) streams10 formed from unstabilized wild straight run naphtha 16 and sulfurbreakpoint cut 18 without added treatment, depending on sulfur contentof high sulfur fuel oil or is added to (b) stream 60 formed fromdistillate hydrotreater 430 comprising wild naphtha and ultra low sulfurdiesel range materials, or (c) stream 70 formed from heavy oilhydrotreater 460 comprising wild naphtha, ultra low sulfur diesel and asecond reduced sulfur stream or the combination effluent 70 fromhydrotreating zone 400, so that the fuel 600 has an actual sulfurcontent at or below a target sulfur content limit level.

In one preferred variation of use of a high sulfur fuel oil in makingfuel composition 600, the sulfur content of such high sulfur fuel oil isdetermined, then the high sulfur fuel oil is either fed as part of thefeed 50 to the solvent separation unit to form a portion of adeasphalted oil stream 80 or combined with one or more distillatestreams of light distillate 24, medium distillate 26, first heavydistillate 26 or second heavy distillate 32 feeds as part of the feed 20to said distillate hydrotreater 430 or combined with one or more heavyoil streams of light vacuum gas oil 36, heavy vacuum gas oil 38 anddeasphalted oil 80, or both distillate streams and heavy oil streams, toform a portion of the feeds to either the distillate hydrotreater 430 orheavy oil hydrotreater 460, or both, as determined by sulfur content ofthe high sulfur fuel oil to optimize adjustment of hydrotreatingconditions in zones 430 or 460, or adjusting both zone, to form a fuelhaving an actual sulfur content at or below a target sulfur contentlimit level.

In another embodiment of this invention, a clean fuel at or below sulfurcontent limit specifications can be formed by use of a heavy residualoil, including a high sulfur fuel oil which is typically atmosphericresidue or heavier, which may have a density or a sulfur or metalscontent which is outside specifications or within typical standards forhigh sulfur fuel oil. Often, due to market considerations such heavyresidual oil is available from a different source of supply than withinbattery limits of a fuels plant. The heavy residual having a sulfurcontent greater than the target sulfur content limit level of fuel 600is fed to one or more of (a) vacuum distillation tower 200 separately orcombined via line 30 with atmospheric residual feed to vacuum tower 200to produce at least a portion of any or all of said a second heavydistillate 32, light vacuum gas oil 36, heavy vacuum gas oil or vacuumresidual 50, or (b) to solvent separation 300 separately or combined vialine 50 with vacuum residual feed to solvent separation 300 to produceat least a portion of deasphalted oil 80 or pitch 90 having metals richheavy residual that is passed to gasification system 500 forgasification, sulfur recovery and other ancillary processing. Such heavyresidual oil may also be combined with pitch via line 90 as feed to theutilities island 500. In variations, when untreated high sulfur fuel oilwith relatively high sulfur (in excess of 0.5 wt. %) or high metalscontent is used without treatment for trim for adjustment of fuel 600sulfur content of this invention, such use is in relatively minoradjustment amounts when used without treatment to ensure the combination600 does not exceed target sulfur content limits.

The FIG. 2 flowsheet showing various intermediate individual productsare for illustration and understanding of the main products andbyproducts at effluents of each unit operation depicted. A selectedvariation of separation or treatment by each unit operation depends oncrude and feeds selected and optimization of intermediates produced toproduce fuel at or below target sulfur specification. For example, botheffluents 60 and 70 from hydrotreaters 430 and 460 can be combinedwithin hydrotreating zone 400 by use of a common gas-liquid separator(not shown) if ultralow diesel produced in zone 430 is not separated outand all hydrotreated materials are combined in line 70 as shown in FIG.2, only gases are removed. Alternatively, if separation or removal ofpart of some wild naphtha or ultralow sulfur diesel for trim control offinal combination zone 600 fuel sulfur content or for other reason is aprocess objective, effluents 60 and 70 from hydrotreaters 430 and 460can be sent, either separately or combined to a stripper or fractionatorto enable removal of a fraction of wild naphtha or ultralow sulfurdiesel.

Although the various embodiments of the invention have been described,it is to be understood that they are meant to be illustrative only andnot limiting. For illustration, when flashpoint of fuel is not aconsideration, an untreated light tight oil or condensate, or acombination of untreated light tight oil or condensate, having lowmetals content and a sulfur content less than the target sulfur contentis added as portion of the combination of said untreated fractions withsaid treated streams to form a fuel having an actual sulfur content ator below a target sulfur content. The term “light tight oil” or “LTO”,as used herein means a well head condensate or shale gas condensatehaving (i) sulfur content in the ranges of 0.1 wt. % to 0.2 wt. % and a(ii) a density, API (Deg) in the range of 38 to 57 and (iii) widevariations of hydrocarbon ranges based sources. LTOs typically haveprospective overlapping distillation cut fraction ranges, in weightpercent of mass, of (a) 5 to 20 wt. % liquefied petroleum gas range, (b)10 to 35 wt. % naphtha, (c) 15 to 30 wt. % kerosene, (d) 15 to 25%diesel, (e) vacuum gas oils and (f) no (0%) to 10% heavy residuals.

In one variation, this invention addresses co-processing of (i) a crudehaving the quality of untreated light tight oil or condensate, or acombination of light tight oil or condensate, for example, whenavailable oil production basins from outside the battery limits of fuelproduction plant of this invention with (ii) with one or more othercrude feeds to a process of this invention produce a low cost fuelhaving low metals content and a sulfur content less than a target sulfurcontent. Such light tight crude, with no (e.g. 0% or very low heavyresiduals) likely do not contain sufficient heavier hydrocarbons withinits bottoms fractions with residuals ranges to providing processingbalance for desulfurization or other hydrotreating, nor correspondingresiduals sufficient to support process hydrogen generation to enablecost effective processing such light crude to hydrogenate to lowersulfur and metals for decontamination or sufficient lubricity to supportuse in certain types of engines.

Embodiments of novel fuels of this invention are better appreciated withreference to ISO 8217 standard issued by International Organization forStandardization (ISO). ISO 8217 describes categories and detailedspecifications for a range of marine residual fuels for consumption onboard ships. The specifications acknowledge, as a basis for theirdevelopment, variations in crude oil supplies, refining methods, andother conditions. Such specifications indicate they take into accountvarious international requirements for such properties as sulfurcontent. The current strictest ISO 8217 is RMA 10, to whichinterpretation of specification and claims should be based. Based onsimulated compositions of the novel fuels of this invention (being madeby simulation model splitting crude into fractions, some of which arehydrotreated, and excluding residue which not solvent during solventseparation and then reconfiguring such untreated and treated segments),these novel meet and/or exceed all ISO RMA 10 specifications exceptflashpoint which, for cargo ships, falls within SOLAS exceptions forflash point requirements for cargo ships, which fuels have novelcharacteristics or improvements which we claim distinguish these novelfuels from such marine fuels from residuals.

In one variation, we provide an improved fuel meeting or exceeding allISO RMA 10 (ISO 2817-10) specifications except flashpoint and having anyor all of the following distinguishing characteristics: (a) sulfur at0.50% m/m (wt. %) or below, preferably in the range of 0.05 to 0.20 m/m(wt. %), (b) metals at 5.0 mg/Kg (ppmwt) or below, preferably 1.0 mg/Kg(1.0 ppmwt) or below such as at 0.2 mg/Kg (0.2 ppmwt), and (c)flashpoint at not more than 60° C. and other improved features over ISORMA 10 specifications. In variations, these novel fuels have having oneor more of these additional distinguishing characteristics: (a)viscosity at not more than 10 cSt, (b) a pour point of 0 (zero) ° C. orless, (c) density in range of 820 to 880 Kg/M³′, (d) CCAI at not morethan 800, (e) sodium at 20 mg/Kg or below, preferably 10 mg/Kg or below.All of the foregoing are determined by testing or computations methodsspecified by ISO 2817-10. Such fuels comprise a range of hydrocarbonshaving an initial boiling point of naphtha and highest boiling pointbeing that of the highest boiling point of the component thereof whichis soluble in a solvent suitable for solvent separation, such asheptane. Metals can be reduced to as low as 100 ppbwt, depending feedcomposition and adjustment of operating conditions.

We have discovered we can produce in a low cost manner such extremelylow sulfur and metals fuels which fall within a SOLAS exception forflashpoint requirements for cargo ships. If flashpoint treatment isrequired for other uses, flashpoint treatment to have flashpoint at 60°C. or above, or such requirement, known in the art.

Using a low viscosity, low pour point fuel of this invention in marineengines to avoids or reduce energy consumption required in connectionwith heating conventional residual oils to enable their pumping andhandling, either in port at fueling stations or at sea. Heavy residualoils are thick, need to be heated, and kept hot, because of theirrelatively high pour point and high viscosity, during all of storage,pumping, and feeding to marine engines, which heating consumes energy.

Table 1 below is shows two variations of fuels of this invention, beingone with an extremely low sulfur content of 0.1 wt. % and the other atan even more reduced level of 0.05% wt. %, sulfur compared against ISORMA 10 set forth in Table 1 below:

TABLE 1 Example fuel of Example fuel of ISO this Invention thisInvention Simulated RMA at target sulfur at target sulfur ISO ProposedCharacteristics 10 content limit content limit Test Method for For ISO8217 Unit Limit Spec of 0.05 wt. % of 0.1 wt. % Reference as citedKinematic viscosity mm²/s where max. 10.00 10.00 10.00 ISO 3104 at 50°C.^(b) 1 mm²/s = 1 cSt min. Density at 15° C. Kg/M³ max. 920.0 880.0880.0 see 7.1 ISO 3675 min. 820.0 820.0 or ISO 12185 CCAI max 850 762762 See 6.3a) Sulfur wt. % Statute Statute 0.05 0.10 see 7.2 ISO 87540.10% in ISO 14596 ECA 3.50% out ECA at 2016 Flashpoint ° C. min 60.0<60 <60 Hydrogen sulfide mg/kg max. 2.00 2.00 2.00 IP 570 Acid number mgKOH/g max. 2.5 0.05 0.05 ASTM D664 Total sediment aged mass % max. 0.10.05 0.05 see 7.5 ISO 10307-2 Carbon residue: mass % max. 2.50 1.5 1.5ISO 10370 micro method Pour point winter C. 0 0 0 ISO 3016 (upper)^(f)quality summer C. 6 0 0 ISO 3016 quality Water Volume % max. 0.30 0.300.30 ISO 3733 Ash mass % max. 0.040 0.03 0.03 ISO 6245 Vanadium mg/kgmax. 50 0.2 0.2 see 7.7 IP 501, IP 470 or ISO 14597 Sodium mg/kg max. 5010 10 see 7.8 IP 501 IP 470 Aluminum + max. max 25 0.2 0.2 see 7.9 IP501, Silicon IP 470 or ISO 10478

Such fuels of this invention having the properties shown in Table 1 arefurther distinguished in comprising the substantially the entire rangeof crude oil derived hydrocarbons from C3 or C5 to greater than C20,said hydrocarbons having an initial boiling point being the lowestboiling point of any fraction of said crude oil at atmosphericdistillation conditions and highest boiling point being the finalboiling point of the residual portion of said crude oil which is notsoluble in a solvent suitable for solvent separation. Opposite thereto,residuals, whether vacuum distillation residual, solvent deasphaltingresidues, other cokers and the like do not contain such broadhydrocarbon range but are limited only very heavy materials.

From the disclosure in the specification and claims, this inventionenables manufacture of ultraclean fuels that meet or exceeds standardsfor compatibility with current marine reciprocating engines but also arecompatible with advanced combustion gas turbines that can be used inmarine applications. Such advanced turbine engines are available todaybut are typically land based. These advanced turbine engines, oncemobilized on board ships, can have a large efficiency advantage, withless corrosion or ash formation, by firing the fuels of this inventionduring voyage. Also, depending on available fuel economics at port,ships can gain efficiency advantage by filing these novel fuels at portto generate electrical power and transmit such power to local electricgrid for revenue. Such revenue from in port power generation offsets atsea fuel costs and can drop the actual total at sea fuel cost to theship to less than high sulfur fuel oil and thus offsets costs of use oflow sulfur fuels of this invention if such are a more expensive voyagefuel. The ultimate gain is for the environment, when in certain basecase comparisons, it is possibly to achieve more than a ninety fivepercent (95%) reduction in SOx and NOx emissions and potentially greaterthan 99% (almost 100%) reduction emissions of noxious metals emissionsduring voyage. In addition, the environment benefits from a CO2reduction from two ways: (i) efficiency of advanced gas turbine engineson ships and (ii) efficiency of power generation at ports, whereinefficient firing of coal, crude oil, residual oils or certain otherfuels is replaced.

Thus, it is apparent that the present invention has broad application toproduction of fuels having reduced, low levels of sulfur and othercontaminants and use of such fuels. Certain features may be changedwithout departing from the spirit or scope of the present invention.Accordingly, the invention is not to be construed as limited to thespecific embodiments or examples discussed but only as defined in theappended claims or substantial equivalents of the claims.

1-44. (canceled) 45-57. (canceled)
 58. A method of combustion by firing a fuel comprising a combination of hydrocarbons from crude oil ranging from the lowest boiling component not treated by hydrogen of an untreated liquid fraction at or below sulfur breakpoint from atmospheric distillation of said crude oil to highest boiling soluble component of hydrotreated solubles from solvent separation of highest boiling liquid fractions over sulfur breakpoint from atmospheric distillation of said crude oil, said fuel further characterized by having sulfur content of 0.5 wt. % or less. 59-66. (canceled) 